Monday, April 30, 2012

While the average pump price of gasoline has held the attention of most Americans for much of this year, the price trend for natural gas has been equally dramatic in the opposite direction. Gasoline prices flirted with the psychologically important $4 per gallon mark for several weeks before receding to around $3.82 today. Meanwhile natural gas prices continued their steady drift downward, briefly crossing $2 per million BTUs (MMBTU) before recovering slightly. To put this in perspective, when the spot price of natural gas bottomed out at $1.82 earlier this month, it was selling for the energy equivalent of oil at $10.56 per barrel. The last time oil prices were that low was during the Asian economic crisis of the late 1990s, and we're still feeling the consequences of that crash. The longer-term impact of today's dirt cheap natural gas is likely to be quite different, however.

Oil and natural gas used to be joined at the hip, and in the minds of many people they still are, even though the days when most US natural gas was a direct or indirect byproduct of oil production--either produced with oil or found by accident when a company was drilling for oil--are long past. The vast majority of our gas comes from dedicated gas wells in fields that were explored because of their gas potential, with shale gas and other so-called "tight gas" increasingly dominating output. The widely discussed shale gas revolution is the main reason natural gas is so cheap today, instead of costing over $10 per MMBTU as it would if shale gas hadn't happened and the industry's expectations about increasing LNG imports had materialized instead. Unfortunately for producers, because the surge of shale production has coincided with a weak US economy that is still struggling to get out of first gear, post-recession, the shale gas bounty is turning into a temporary glut.

Here's why the distinction between modern oil and gas production dynamics matter. When oil prices crashed in the late 1990s due to the combination of weaker-than-expected global demand and growing production, producers cut investments and scaled back new projects. Because of the time lags inherent in big oil projects the impact of those decisions was felt in the middle of the last decade, just as demand growth in the developing world hit its stride. Other things were happening, as well, but there's a good case that $10 oil in the late '90s helped set up $145 oil in 2008 and contributed to the persistence of prices well over $100/bbl today. So is the current natural gas price slump setting up a spike back over $10/MMBTU within a few years? I think that's unlikely, though I do believe gas prices will recover somewhat.

My reasoning involves several key differences between the oil and gas markets. First, the gas lifecycle is much quicker, at least where pipeline infrastructure is already in place. More than half of today's US gas production comes from wells drilled in the last 5 years. Gas drilling has already slowed, and more rigs are being redeployed to pursue much more valuable oil plays, but drilling could switch back to gas just as quickly. Then there's the underlying resource, which would support even higher gas production than today's for many decades. Finally, we have the factor referenced by Chesapeake Energy's controversial CEO, Aubrey McClendon in an interview in this weekend's Wall St. Journal: new demand.

The only reason that additional demand from utilities, petrochemicals, transportation, and exports hasn't already sopped up the gas surplus and boosted prices is that all of these developments involve time lags of their own. It will take time to build the new ethylene crackers announced by Shell and Dow Chemical. Natural gas power plants have already ramped up output and seized market share from coal, but bigger shifts will require more gas turbines. Converting long-haul trucking to natural gas requires expensive modifications to trucks and new refueling infrastructure. Meanwhile the first liquefied natural gas export terminal just received the go-ahead from FERC. Yet while none of these things can happen overnight, and there isn't enough gas to push them all to their maximum potential in any case, they are all being propelled by the enormous driving force of natural gas at the oil equivalent of $12-20/bbl in a $100-per-barrel world. The developers of renewable energy technology must also figure out how to compete with that, if they're going to prosper without fiscally unsustainable subsidies.

As scaled-back drilling and new demand mop up the current gas glut, only one thing can happen to prices. The $64,000 question is how high they could rise and still keep the demand expansion going. A return to $10 natural gas would halt the shift from coal to gas and stop the penetration of gas in transportation in its tracks, but it would also unleash an even larger wave of new production. Mr. McClendon's latest guess for the medium-term price is between $3 and $5, and that sounds reasonable. Even at the latter the BTUs in gas would still cost just $29/bbl. We won't see oil at that price any time soon, so gas doesn't need to remain at $2 to create a world-beating energy advantage for the US. If natural gas can fulfill even a portion of the potential we see today, we will soon need to rethink most of our assumptions of energy scarcity embedded by four decades of recurring oil crises. That will be uncomfortable for some people.

Wednesday, April 25, 2012

The quality of media reporting on energy has improved significantly since I started this blog in 2004. However, one subject on which I think the state of energy reporting still leaves much to be desired concerns the role of market speculation in setting oil prices. It's a complex issue, and it has become highly politicized this year. Doing it justice requires more than just the obligatory video of the New York Mercantile Exchange (NYMEX) or interview with a "floor trader". I've encountered plenty of speculation on how much lower prices might be without the influence of speculators, but I've yet to see anyone go the next step to ask how prices might be set in the absence of any speculation at all. This is an important question, because the primary benefit of the futures markets in which speculators participate is transparent price discovery. I'd like to offer some perspective on that from my own experience trading oil and its products in the 1980s and early 1990s.

Imagine a world in which we're not really sure what the price of oil is on a given day. If that seems a bizarre notion, it's because the media have made the prices of oil futures contracts in New York and London nearly as ubiquitous as those of the Dow Jones and other stock market indices. That wasn't always the case. I can remember many occasions on which the price of an energy commodity was hard to determine, or was simply what a particular buyer or seller said it was that day.

When I started trading petroleum products in the mid-1980s, the NYMEX contract for West Texas Intermediate crude oil was relatively new, and the heating oil contract had only been around a few years longer. Their influence wasn't nearly as pervasive as now, beyond the localized Gulf Coast light crude and New York Harbor heating oil markets they were devised to support. The spot market transactions that I executed on behalf of Texaco's US west coast operations normally involved a fixed price arrived at through one-on-one negotiation, based on the buyer's and seller's perceptions of the market from other conversations, with input from limited and often suspect reporting on recent, similar transactions. When I shifted over to trading crude oil a few years later, most deals were still based on the system of "posted prices" that had existed for decades, in which producers and refiners issued periodic bulletins listing the current prices at which they solicited offers for each specific grade of oil in which they were interested. We bought or sold at small premia or discounts to the relevant posting--up to "P-plus" a dollar per barrel or so--with minor adjustments for actual quality received. Transactions for OPEC crude were similarly based on the producing country's official posted prices, which sometimes didn't change for months.

In other words, it's not so long ago that prices for many grades of oil or refined products were often either obscure or inflexible, and largely determined by an exclusive "club" of participants. Moreover, there were times when it simply wasn't possible to buy or sell a commodity when needed, because there were no active sellers or buyers. The management of my business unit had a strong bias against doing business with independent trading companies, the speculators of the day, but when we needed to buy gasoline or a cargo of crude oil because we were about to run out, and they were the only ones selling because our competitors were either in the same position as we were or didn't care to assist us in competing with them, then managers were usually willing to set aside those scruples. The nascent futures markets were an exception to that system, and as they grew in influence--complete with speculation--more and more business was transacted on the basis of an agreed premium or discount to a particular NYMEX contract. It wasn't a perfect system, but it had the advantage of greatly increased transparency and liquidity.

When I hear people who have never participated in the oil markets suggest that only those parties with "legitimate" needs to do so should be able to buy or sell futures and options, I wonder if they understand that this path could lead back to a market with inherently less transparency and less competition--one that might in some respects be easier to manipulate, with prices set more arbitrarily than the result they accuse speculators of producing.

In my view the old way of trading oil still has a few things to recommend it, even though it was roughly as prone to sudden spikes as the current system is. However, it's hard for me to imagine that the public and politicians would really prefer to revert to a situation in which oil prices were set between producers and refiners--by OPEC and oil companies, if you will--instead of the present one in which they are determined in a market with much broader participation. I don't even think oil companies would want to go back, because they're in a much better position to defend their profitability when they can state with confidence that they don't actually set prices.

I realize that I've set up a more extreme choice than most of those who are unhappy with the current situation would advocate; most of them appear to want to restrain speculation, rather than eliminating it entirely. Yet I wonder whether that nuance is any more realistic, or helpful. I believe that the distinction that ought to be drawn more sharply is not between speculation and the participation of "legitimate" players, but between trading for either hedging or profit and attempts to manipulate prices. It's one thing to bet on the price of oil going up or down, which after all requires someone else to take the opposite bet. It's quite another to try to rig the game in your favor.

Tuesday, April 17, 2012

One of the biggest challenges in assessing the environmental benefits of electric vehicles is that electricity is generated in so many different ways, with differing costs and consequences, and that patterns of generation vary by region, season, and time of day. As a result, categorical claims that EVs are always greener than the hybrids against which they compete most directly, or even compared to efficient non-hybrid compact gasoline or diesel-powered cars, must be suspect. The Union of Concerned Scientists (UCS) has just issued a report that takes some of the mystery out of such comparisons, including a helpful map showing likely greenhouse gas emissions associated with EV use expressed in terms of equivalent miles per gallon from a gasoline vehicle. The takeaway is that as of now, the emissions advantage of purchasing an EV depends heavily on where you live, with equivalent emissions from average grid power in many parts of the country about on a par with those from a small car like the Chevrolet Cruze, and not even as good as from a Prius-type non-plug-in hybrid.

This apparent paradox becomes clearer when you examine the cities map that the New York Times distilled from the report, reflecting the local basis of electricity generation. An EV operated in L.A. or San Francisco would unambiguously beat a Prius on emissions, while an EV in my neighborhood in Northern Virginia would have only a slight edge, and one in Denver would yield emissions comparable to an ordinary car getting 33 mpg, unless the owner was scrupulous about recharging only when greener power was available. That's because despite the declining share of coal-fired power in our national generation mix, there are still many regions and locales where coal dominates the grid, and the GHG emissions from coal-fired generation are considerably higher than from natural gas or low-emission nuclear and renewables.

Any report such as this must incorporate a number of assumptions, and from my fairly quick perusal of the details they seem generally well-identified here. The UCS's emission-equivalent miles per gallon calculation is based on a Nissan Leaf getting 3 miles per kilowatt-hour (kWh.) Grid emissions are calculated using a model of average hourly emissions over the course of the year. It didn't appear that these hourly-averaged figures were weighted for seasonal variations in driving patterns, but that's probably more nuance than is necessary at this level of scrutiny.

The report also includes information about recharging costs in different locations under different rate plans. Prospective EV buyers would benefit from taking the time to understand what these issues mean in their specific locations before investing in one. From my perspective, the report should also provide serious food for thought for policy makers concerning the wisdom of a single federal tax credit for EV purchasers in the US. As hard as that policy is to justify in the best of locations, based on the equivalent cost per ton of CO2 avoided, it looks positively senseless in locations where coal is still king. And while the report makes the point that the generation mix in many regions will become cleaner over time as utilities respond to renewable portfolio standards and other policies, buying an EV in a high-emissions region and counting on that factor to improve the car's environmental benefits during its lifetime seems like a risky bet, particularly in economic terms.

The biggest caveat I'd offer about the report concerns its emphasis on comparing EVs to non-hybrid compact cars, both on costs and emissions. That just doesn't seem realistic, given the array of choices and types of consumers in the market. While the number of consumers willing to consider an electric vehicle is increasing, the "take rate"--the number who actually convert their interest into a purchase decision, remains minuscule, resulting in sales of just 0.3% of all US cars sold in March. Meanwhile hybrids have benefited from rising gas prices to hit 3.4% of sales. It's also worth recalling that the fuel, emissions and dollar savings from improved fuel economy decline with each additional increment. Hybrids already capture the most valuable savings over conventional cars, while the incremental fuel savings from stepping up from a hybrid to an EV are roughly comparable to what hybrids achieve, but require additional battery capacity and electricity, neither of which is free. That makes hybrids the technology for EVs to beat. As helpful as the information provided in the UCS report should be for consumers, the ultimate decision to buy an EV seems driven more by values than value, at least until EV costs fall significantly.

Wednesday, April 11, 2012

How often have we heard that installing renewable energy sources like wind and solar power will improve US energy security and reduce oil imports? There are other reasons for promoting these technologies, but this one has little substance, because we generate less than 1% of our electricity from oil. Ironically, this logic looks much more relevant to the part of the world with the largest oil reserves and that accounts for the lion's share of global oil exports, the Middle East. This week's Economist reports that Saudi Arabia generates 65% of its power from oil, and the impact on its oil exports could grow dramatically as the country's population and economy expand. Other Gulf producers have similar profiles. The Saudi government's strategy to increase its use of nuclear and renewable energy could pay big dividends in preserving oil for exports, though the volumes freed up by such means wouldn't be cheap.

Saudi Arabia has set a goal of deriving 10% of its electricity from renewable sources by 2020. Solar power looks like the leading option, and a Saudi company recently announced a deal to build a plant to produce polysilicon, the raw material for many of today's photovoltaic (PV)cells. (Its output would likely be exported for some time, until the downstream value chain developed.) Saudi Arabia has tremendous solar potential, with much of the country receiving more than 6 hours per day of peak sunlight, on average. Based on recent electricity demand of around 200 billion kilowatt-hours (kWh) per year, it would take roughly 9,000 MW of PV capacity to achieve their goal. How much oil would that save, and at what effective cost?

With average Saudi power generation operating at 31% efficiency, according to a report by ABB, saving the oil used to generate 20 billion kWh would free up roughly 100,000 bbl/day for other uses, including exports. That doesn't sound like a lot for a country that's currently producing 10 million bbl/day, but it's the equivalent of a medium-to-large offshore oil platform. However, the more interesting aspect of this strategy is its cost, both in aggregate terms and in the effective cost of the oil it would release.

A recent report from Lawrence Berkeley National Laboratory estimated the installed cost of utility-scale solar power in the US last year at around $4 per Watt. Assuming current costs are 10% lower--module costs have fallen by more, but balance-of-system costs typically fall more slowly--that would result in a required investment of $32 billion at today's prices. That's about what ExxonMobil spent on its entire global oil & gas development program last year, which will presumably yield a lot more than 100,000 bbl/day of future production. Moreover, using NREL's simplified model for calculating levelized electricity costs from different technologies, the output of PV in Saudi Arabia at $3.60/W installed would cost around $0.13/kWh without subsidies. Using that same 31% efficiency factor for oil-fired power generation yields an effective cost for each barrel saved by solar power of $70. That looks cheap compared to current oil prices, but it's almost an order of magnitude higher than what many assume it costs the Kingdom to produce a barrel of oil today. Even if we assumed installed PV costs fell to $2/W before they're done, that's still around $40/bbl. If that looks attractive to them, what does it say about their other opportunities?

One way to address that without getting into thorny questions about peak oil is to consider the alternative of using gas-fired generation to displace oil from Saudi Arabia's power sector. The Kingdom has the world's fifth-largest natural gas reserves. At 264 trillion cubic feet they appear more than ample for the purpose, if developed. Even if gas from new fields cost $5 per million BTUs, the effective cost of the oil freed up by switching to efficient gas-fired combined cycle power generation would be about $25/bbl. And with recent trends showing the energy intensity of the Saudi economy getting worse, not better, the scale of the efficiency opportunity there indicates that the cheapest displaced barrels might be from investments in improving energy efficiency, rather than new generation of any kind.

I'm not suggesting that solar power has no place in Saudi Arabia's energy mix. If the technology makes sense anywhere, it is in sunny countries like this that rely on expensive fuels for most of their current generation. Yet as clever and appealing as the idea of using abundant solar energy to free up Middle East oil for export might sound, from both an environmental and oil-consumer perspective, the numbers suggest that it's probably not even their second- or third-best option for that purpose.

Friday, April 06, 2012

Has the high cost of fuel got you down? Why not buy your own oil refinery? That's apparently what Delta Air Lines is considering. With jet fuel purchases constituting one of the largest operating costs for carriers like Delta, and with several refineries in the Northeast US facing permanent closure due to poor profitability, it's not hard to see why this idea would seem attractive, at least superficially. However, there are a host of reasons why most of the press I've seen on this story is negative, including today's Heard on the Street column in the Wall St. Journal, entitled, "Delta Chases Fuel's Gold." The fundamental problem is the same one that has made me skeptical about the benefits of airlines investing in the production of renewable aviation fuel: Any advantageous pricing they may choose to provide to their airline division must come at the expense of lost opportunities for the fuels business, because the value of that fuel is set by the market.

How a company should reflect such opportunity costs in its inter-departmental transfer pricing is an age-old problem. I dealt with this routinely when I traded refined products for Texaco's west coast refining and marketing business in the 1980s. The marketing department always wanted to receive the output of the refineries at a lower price than we were charging them, so that they could capture market share and justify investments in new and remodeled gas stations. But making them look good at the cost of the refineries just made it harder to justify the investments needed to keep the refineries operating efficiently and in compliance with current and future regulations. Delta might buy ConocoPhillips' Pennsylvania refinery at a low price today, but they could be forced to invest at least as much within a few years to meet new gasoline sulfur regulations or other changes. It doesn't trivialize the situation to put it into the category of no free lunches.

Then there's the question of reorienting a refinery to make a lot more jet fuel that it has done historically, as one article suggested Delta was considering. Modern refineries are fairly flexible, and it would be possible to do that to some degree, though within limits that would require significant investments to exceed, making the proposition look much less attractive. Moreover, refineries optimize their output every day to make the slate of products that yields the highest profit, as crude and product prices fluctuate. Steering a less flexible course would almost certainly make the facility less, not more profitable, and it's only on the market because it wasn't sufficiently profitable as it was.

The only scenario in which I could see this idea actually working to Delta's benefit is if the refinery closures now being planned tightened the supply of jet fuel into the New York market so significantly that Delta was able to effectively corner that market, forcing other airlines to pay it a significant premium, either in cash or in jet fuel supply in other locations, while artificially keeping costs for its own flight operations low and allowing it to expand its share of the important NY air market. But New York isn't some isolated inland location, and they'd always be competing with jet fuel cargoes brought in by vessel, or with fuel shipped from Gulf Coast refineries via the Colonial Pipeline, which is expanding to meet the new demand its faces in light of the pending refinery closures. They might eke out a few extra cents, but would that be enough to justify taking on the enormous capital and operating costs--not to mention the substantial operating risks--of owning a refinery? If Delta has discovered some enticing angle I've missed, I'd love to know what it is.